This section is intended to introduce various aspects of the art, which may be associated with exemplary embodiments of the present disclosure. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present disclosure. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.
Field of the Invention
The present invention relates to the field of well drilling and completions. More specifically, the invention relates to the transmission of data along a tubular body within a wellbore. The present invention further relates to the monitoring of annular conditions behind a casing string using sensors and acoustic signals.
General Discussion of Technology
In the drilling of oil and gas wells, a wellbore is formed using a drill bit that is urged downwardly at a lower end of a drill string. The drill bit is rotated while force is applied through the drill string and against the rock face of the formation being drilled. After drilling to a predetermined depth, the drill string and bit are removed and the wellbore is lined with a string of casing. An annular area is thus formed between the string of casing and the formation penetrated by the wellbore.
A cementing operation is typically conducted in order to fill or “squeeze” part or all of the annular area with a column of cement. The combination of cement and casing strengthens the wellbore and facilitates the zonal isolation of certain sections of a hydrocarbon-producing formation (or “pay zones”) behind the casing.
In most drilling operations, a first string of casing is placed from the surface and down to a first drilled depth. This casing is known as surface casing. In the case of offshore operations, this casing may be referred to as a conductor pipe. One of the main functions of the initial string of casing is to isolate and protect the shallower, fresh water bearing aquifers from contamination by wellbore fluids. Accordingly, this casing string is almost always cemented entirely back to the surface.
One or more intermediate strings of casing is also run into the wellbore. These casing strings will have progressively smaller outer diameters. Each successive pipe string extends to a greater depth than its predecessor, and has a smaller diameter than its predecessor.
The process of drilling and then cementing progressively smaller strings of casing is repeated several times until the well has reached total depth. A final string of casing, referred to as production casing, is used along the pay zones. In some instances, the final string of casing is a liner, that is, a pipe string that is hung in the wellbore using a liner hanger. The final string of casing is also typically cemented into place.
Additional tubular bodies may be included in a well completion. These include one or more strings of production tubing placed within the production casing or liner. Each tubing string extends from the surface to a designated depth proximate a production interval, or “pay zone.” Each tubing string may be attached to a packer. The packer serves to seal off the annular space between the production tubing string(s) and the surrounding casing. The production tubing provides a conduit through which hydrocarbons or other formation fluids may flow to the surface for recovery.
In most current wellbore completion jobs, especially those involving so called unconventional formations where high-pressure hydraulic operations are conducted downhole, the casing strings are entirely cemented in place. Hydraulic cements, usually Portland cement, are typically used to cement the tubular bodies within the wellbore. During completion, it is important that the cement sheath surrounding the casing strings have a high degree of integrity. This means that the cement is fully squeezed into the annular region to prevent fluid communication between fluids at the level of subsurface completion and any aquifers residing just below the surface. Such fluids may include fracturing fluids, aqueous acid, and formation gas.
Heretofore, the integrity of a cement sheath has been determined through the use of a so-called cement bond long. A cement bond log (or CBL) uses an acoustic signal that is transmitted by a logging tool at the end of a wireline. The logging tool includes a transmitter, and then a receiver that “listens” for sound waves generated by the transmitter through the surrounding casing strings. The logging tool includes a signal processor that takes a continuous measurement of the amplitude of sound pulses from the transmitter to the receiver.
The theory behind the CBL is that the sound pulses will generally have a consistent amplitude when pulses are sent at the same frequency. However, if a section of pipe is not fully cemented in place, meaning that a gap exists in the cement sheath, the steel material making up the casing string will have more of a “ring” in response to the acoustic signal. This will manifest itself in the form of a greater amplitude of the sound pulses. Bond logs may also measure acoustic impedance of the cement or other material in the annulus behind the casing by resonant frequency decay.
Cement bond logs are typically run after a casing string has been cemented in placed within the wellbore. However, it is desirable to be able to evaluate the integrity of the cement sheath behind the casing string immediately after the cementing operation has been conducted and without need for a wireline or separate logging tool. Further, it is desirable to determine the progress of cement placement during the cementing operation using a series of communications nodes placed along the casing string as part of the well completion.
Another issue encountered during cementing operations relates to a so-called trapped annulus. A trapped annulus occurs when the fluid behind a casing string becomes sealed under pressure. This can be caused by cement or settled mud solids extending above the shoe of the outer string of casing while the top of the annulus is sealed by the design of the wellhead. When the fluid inside a trapped annulus is later heated by the production of reservoir fluids, the pressure in the annulus builds. This pressure can exceed the pressure rating of the inner string of casing. This, in turn, can lead to pipe collapse or even well failure.
Annular pressure cannot be detected using a CBL log. Further, in the context of subsea wells, subsea annular pressure generally cannot be monitored with permanent downhole pressure gauges that communicate information back to the surface using wires or cables. This is because electrical and optical conduits generally should not be passed through a subsea wellhead. Accordingly, a need exists for a wireless sensor network, such as an acoustic telemetry system, that enables the operator to receive signals from sensors along the casing, and to also transmit signals to a tool in a subsea well using high data transmission rates. Such signals are indicative of an annular condition, both at the time of cementing and shortly after completion.